This invention relates to downhole gas compression, and in particular to the provision of a gas compression system suitable for use in downhole applications, and having utility in facilitating recovery of natural gas from subsurface hydrocarbon-bearing formations.
In oil and gas production operations, a drilled bore extends from surface to intersect a hydrocarbon-bearing formation. The hydrocarbon may be in the form of a liquid or gas, or a mixture of both; for brevity, reference will be made primarily herein to production of gas. Initially, the gas, known as the produced gas, is often at sufficient pressure that it will flow from the formation, through the well bore, to surface. As the gas travels up through the bore the gas cools, and the gas velocity must be sufficient to carry the resulting condensates to surface. However, when a well has been producing gas for some time and the volume of gas remaining in the formation has decreased, often referred to as a depleting gas well, the formation pressure may fall below the wellhead manifold pressure, or the difference between the reservoir pressure and wellhead pressure may be such that a satisfactory flow rate from the well cannot be maintained; the gas must then be pumped out of the well. This is most effectively achieved by compressing the gas at a point in the well, preferably close to the production formation. However, there are many difficulties associated with compressing gas in the well, some related to the restricted space available in the well to accommodate the compressor, and also the difficulty in supplying power to the compressor.
To achieve the pressures sought in the space available, it is generally considered necessary to utilise a high speed compressor. WO 97/33070 (Shell Internationale Research Maatschappij B.V.) describes a downhole multistage rotary compressor driven by a brushless permanent magnet motor and described as being capable of operating at a speed above 5000 rpm. To reduce friction within the compressor, the compressor shaft journal bearings are gas lubricated, the gas being the produced gas which is supplied to the bearings via a small auxiliary compressor unit mounted to the main compressor. The motor and optional gearbox must however be liquid cooled and lubricated, and are therefor located in appropriate liquid-filled chambers isolated from the compressor by conventional seals.
It is among the objectives of embodiments of the present invention to provide a downhole compression system which provides an improved performance over existing proposals.
According to a first aspect of the present invention there is provided a downhole gas compression system adapted for location in a bore, the system comprising an axial flow compressor and a gas-filled electric drive motor.
The invention also relates to a method of compressing gas downhole, utilising a compressor driven by a gas-filled electric motor.
The use of a gas-filled motor avoids the friction losses associated with conventional oil-filled motors; friction losses in the rotor/stator gap and churning losses in oil-filled motors place restrictions on the speeds such motors may achieve while containing losses within tolerable levels.
The gas utilised to fill the motor may vent into the well bore, and join the produced fluid, preferably via gas valves which operate as gas seals in the opposite flow direction, preventing ingress of well fluids to the motor in the event of loss of supply gas pressure.
Conveniently, the motor and compressor are substantially axially aligned within an elongate housing, such that they may be accommodated in the confines of a well bore.
Preferably, the motor is gas lubricated, with gas being supplied to the motor bearings, which bearings are preferably hydrodynamic, but may alternatively be hydrostatic.
Preferably both the compressor and motor are liquid free, that is, the compressor set does not contain any liquids such as water, liquid hydrocarbons, liquid lubricants and the like.
Preferably, the motor is also gas cooled. In one embodiment, this allows use of produced gas to cool the motor, which gas may be directed over or around the motor as appropriate, such that the motor does not have to be contained within a finite volume of liquid, typically a lubricating oil, held in a fluid-tight housing; as described in WO 97/33070, this conventional arrangement places restrictions on the energy which may be added to the gas, as the compressed gas must be maintained at a temperature low enough to permit cooling of the oil and to avoid a phase change of the liquid motor lubricants.
Preferably, the motor drives the compressor directly, preferably on a single shaft, such that there is no requirement for a gearbox requiring liquid lubrication and cooling, and thus high speed shaft sealing arrangements.
Preferably, the motor is a brushless permanent magnet motor, and thus typically of relatively high efficiency, and most preferably of one or both of high electrical frequency and variable speed. Such a motor, if gas filled and gas lubricated, may be driven at high speeds, typically between 20,000 and 70,000 rpm; the optimum speed will depend on a number of factors, including the available bore diameter, the location of the compressor in the bore, and the properties of the produced gas. The motor may be powered by electrical supply from surface, via an inverter.
In one embodiment, a plurality of motors and compressors are provided; the compressors may be mounted in series and the motors may be connected in parallel. A motor controller and inverter may be mounted at surface, power distribution to the motors being such that the group of motors operates effectively as a single machine. Alternatively, a plurality of inverters are installed downhole, one for each motor, such that each motor can be controlled separately of the others. This arrangement provides added flexibility in operation, or redundancy, to suit changing well bore flowing conditions.
Preferably, the compressor is gas lubricated, gas being supplied to the compressor bearings, which are preferably hydrodynamic. Alternatively, the bearings may be hydrostatic, however such bearings tend to require a greater gas supply.
Preferably, gas is supplied to one or both of the motor and compressor from surface, and is preferably clean and liquid free produced gas, or other gas which is compatible with the produced gas. The gas may be compressed at surface by an auxiliary compressor. Alternatively, produced gas from the well bore may be utilised. Preferably, this gas is obtained at compressor discharge and is passed through a downhole solids and entrained liquid separator and an auxiliary compression stage before being passed to one or both of the motor and compressor.
The compressor may be single or multistage.
In some applications, where liquid slug flow may occur and which would be detrimental to compressor performance, a liquid separator may be provided before the compressor inlet. Most preferably, the separated liquid is driven, preferably by gravity, back into a section of the formation which is isolated from the production zone. Most conveniently a centrifugal separator, such as a cyclone, is utilised.